UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark one)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		34-1312571 (IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200, Fort Worth, Texas (Address of Principal Executive Offices)		76102 (Zip Code)

(817) 870-2601
(Registrant’s Telephone Number, Including Area Code)

Former Name, Former Address and Former Fiscal Year, if changed since last report: Not applicable

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ     No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o     No þ

155,102,043 Common Shares were outstanding on July 21, 2008.

 

 

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended June 30, 2008

     Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees.

TABLE OF CONTENTS

						Page
PART I — FINANCIAL INFORMATION
		Item 1.		Financial Statements:
				Consolidated Balance Sheets (unaudited)			3
				Consolidated Statements of Operations (unaudited)			4
				Consolidated Statements of Cash Flows (unaudited)			5
				Consolidated Statements of Comprehensive Income (Loss) (unaudited)			6
				Selected Notes to Consolidated Financial Statements (unaudited)			7
		Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
		Item 3.		Quantitative and Qualitative Disclosures about Market Risk			29
		Item 4.		Controls and Procedures			30
PART II — OTHER INFORMATION
		Item 4.		Submission of Matters to a Vote of Security Holders			30
		Item 6.		Exhibits			31

PART I — Financial Information
Item 1. — Financial Statements

RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)

		June 30,				December 31,
		2008				2007
		(Unaudited)
Assets
Current assets:
Cash and equivalents		$	73			$	4,018
Accounts receivable, less allowance for doubtful accounts of $451 and $583			253,512				166,484
Unrealized derivative gain			1,603				53,018
Deferred tax asset			142,552				26,907
Inventory and other			40,371				11,387
Total current assets			438,111				261,814
Unrealized derivative gain			3,218				1,082
Equity method investments			127,812				113,722
Oil and gas properties, successful efforts method			5,205,547				4,443,577
Accumulated depletion and depreciation			(1,043,099	)			(939,769	)
			4,162,448				3,503,808
Transportation and field assets			120,706				104,802
Accumulated depreciation and amortization			(49,443	)			(43,676	)
			71,263				61,126
Other assets			76,804				74,956
Total assets		$	4,879,656			$	4,016,508
Liabilities
Current liabilities:
Accounts payable		$	273,083			$	212,514
Asset retirement obligations			1,609				1,903
Accrued liabilities			53,285				42,964
Accrued interest			20,045				17,595
Unrealized derivative loss			524,354				30,457
Total current liabilities			872,376				305,433
Bank debt			206,000				303,500
Subordinated notes			1,097,356				847,158
Deferred tax, net			535,575				590,786
Unrealized derivative loss			214,111				45,819
Deferred compensation liability			149,537				120,223
Asset retirement obligations and other liabilities			80,846				75,567
Commitments and contingencies
Stockholders’ equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding			—				—
Common stock, $.01 par, 475,000,000 shares authorized, 155,091,558 issued at June 30, 2008 and 149,667,497 issued at December 31, 2007			1,551				1,497
Common stock held in treasury - 155,500 shares at June 30, 2008 and December 31, 2007			(5,334	)			(5,334	)
Additional paid-in capital			1,681,578				1,386,884
Retained earnings			325,488				371,800
Accumulated other comprehensive loss			(279,428	)			(26,825	)
Total stockholders’ equity			1,723,855				1,728,022
Total liabilities and stockholders’ equity		$	4,879,656			$	4,016,508

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands except per share data)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Revenues
Oil and gas sales		$	347,622			$	213,896			$	655,006			$	407,212
Transportation and gathering			1,224				511				2,353				695
Derivative fair value (loss) income			(198,410	)			28,766				(322,177	)			(13,854	)
Other			(359	)			341				20,233				2,302
Total revenues			150,077				243,514				355,415				396,355
Costs and expenses
Direct operating			37,228				24,816				70,178				50,230
Production and ad valorem taxes			16,056				11,230				29,896				21,642
Exploration			19,462				11,725				36,055				23,435
General and administrative			23,938				17,838				41,350				32,516
Deferred compensation plan			7,539				9,334				28,150				20,581
Interest expense			23,842				17,573				46,988				36,421
Depletion, depreciation and amortization			77,463				51,465				149,033				98,797
Total costs and expenses			205,528				143,981				401,650				283,622
(Loss) income from continuing operations before income taxes			(55,451	)			99,533				(46,235	)			112,733
Income tax (benefit) provision
Current			949				(101	)			1,835				283
Deferred			(21,818	)			34,449				(15,228	)			38,896
			(20,869	)			34,348				(13,393	)			39,179
(Loss) income from continuing operations			(34,582	)			65,185				(32,842	)			73,554
Discontinued operations, net of taxes			—				(979	)			—				63,789
Net (loss) income		$	(34,582	)		$	64,206			$	(32,842	)		$	137,343
Earnings per common share:
Basic — (loss) income from continuing operations		$	(0.23	)		$	0.45			$	(0.22	)		$	0.52
— discontinued operations			—				(0.01	)			—				0.45
— net (loss) income		$	(0.23	)		$	0.44			$	(0.22	)		$	0.97
Diluted — (loss) income from continuing operations		$	(0.23	)		$	0.43			$	(0.22	)		$	0.50
— discontinued operations			—				—				—				0.44
— net (loss) income		$	(0.23	)		$	0.43			$	(0.22	)		$	0.94
Dividends per common share		$	0.04			$	0.03			$	0.08			$	0.06

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)

		Six Months Ended
		June 30,
		2008				2007
Operating activities:
Net (loss) income		$	(32,842	)		$	137,343
Adjustments to reconcile to net cash provided from operating activities:
Income from discontinued operations			—				(63,789	)
Income from equity method investments			(19	)			(796	)
Deferred income tax (benefit) expense			(15,228	)			38,896
Depletion, depreciation and amortization			149,033				98,797
Unrealized derivative losses (gains)			2,691				(530	)
Mark-to-market losses on oil and gas derivatives not designated as hedges			299,227				45,789
Exploration dry hole costs			9,256				8,898
Amortization of deferred financing costs and other			1,488				1,076
Deferred and stock-based compensation			43,601				32,689
(Gain) loss on sale of assets and other			(19,972	)			119
Changes in working capital:
Accounts receivable			(94,657	)			(27,179	)
Inventory and other			(29,839	)			260
Accounts payable			22,384				(8,484	)
Accrued liabilities and other			9,739				3,385
Net cash provided from continuing operations			344,862				266,474
Net cash provided from discontinued operations			—				10,189
Net cash provided from operating activities			344,862				276,663
Investing activities:
Additions to oil and gas properties			(407,313	)			(375,360	)
Additions to field service assets			(19,895	)			(13,899	)
Acquisitions, net of cash acquired			(404,922	)			(282,054	)
Investing activities of discontinued operations			—				(7,374	)
Additional investment in other assets			(10,800	)			(93,312	)
Proceeds from disposal of assets and other			66,660				234,326
Purchases of marketable securities held by the deferred compensation plan			(5,848	)			—
Proceeds from the sale of marketable securities held by the deferred compensation plan			3,320				—
Net cash used in investing activities			(778,798	)			(537,673	)
Financing activities:
Borrowings on credit facility			678,000				570,000
Repayments on credit facility			(775,500	)			(575,500	)
Debt issuance costs			(5,510	)			(206	)
Dividends paid			(12,196	)			(8,635	)
Issuance of subordinated notes			250,000				—
Issuance of common stock			288,073				289,563
Purchases of common stock held by the deferred compensation plan			(73	)			—
Proceeds from the sale of common stock held by the deferred compensation plan			4,306				—
Other financing activities			2,891				—
Net cash provided from financing activities			429,991				275,222
Net (decrease) increase in cash and equivalents			(3,945	)			14,212
Cash and equivalents at beginning of period			4,018				2,382
Cash and equivalents at end of period		$	73			$	16,594

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Net (loss) income		$	(34,582	)		$	64,206			$	(32,842	)		$	137,343
Net deferred hedging gains (losses), net of tax:
Contract settlements reclassified to income			31,278				1,165				27,628				(6,270	)
Change in unrealized deferred hedging gains (losses)			(200,173	)			11,396				(281,505	)			(20,132	)
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes			—				782				—				1,120
Comprehensive (loss) income		$	(203,477	)		$	77,549			$	(286,719	)		$	112,061

See accompanying notes.

RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) ORGANIZATION AND NATURE OF BUSINESS

     We are engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range Resources Corporation is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange under the symbol “RRC.”

(2) BASIS OF PRESENTATION

     These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2007 Annual Report on Form 10-K filed on February 27, 2008. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (“SEC”) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements.

     During the first quarter of 2007, we sold our interests in our Austin Chalk properties that we purchased as part of our June 2006 acquisition of Stroud Energy, Inc. (“Stroud”). We also sold our Gulf of Mexico properties at the end of first quarter 2007. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we have reflected the results of operations of the above divestitures as discontinued operations, rather than a component of continuing operations. See Note 5 for additional information regarding discontinued operations.

(3) NEW ACCOUNTING STANDARDS

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurement.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. We adopted SFAS No. 157 effective January 1, 2008 and the adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows. See Note 12 for other disclosures required by SFAS No. 157. On February 12, 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This deferral of SFAS No. 157 applies to our asset retirement obligation (ARO), which uses fair value measures at the date incurred to determine our liability. We are currently evaluating the impact of the pending adoption in 2009 of SFAS No. 157 non-recurring fair value measures.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income or loss. The statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. We adopted SFAS No. 159 as of January 1, 2008 and the impact of the adoption resulted in a reclassification of a $2.0 million pre-tax loss ($1.3 million after tax) related to our investment securities held in our deferred compensation plan from accumulated other comprehensive loss to retained earnings. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. All investment securities held in our deferred compensation plans are reported in the balance sheet category called other assets and total $48.6 million at June 30, 2008 compared to $51.5 million at December 31, 2007. As of January 1, 2008, all of these investment securities are accounted for using the mark-to-market accounting method, are classified as “Trading” and all subsequent changes to fair value will be included in our statement of operations. For these securities, interest and dividends and the mark-to-market gains or losses are included in the income statement category called deferred compensation plan expense. For second quarter 2008, interest and dividends were $79,000 and the mark-to-market was a loss of $666,000. See Note 12 for other disclosures required by SFAS No. 159.

(4) ACQUISITIONS AND DISPOSITIONS

Acquisitions

     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statements of operations from the closing date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.

     In second quarter 2008, we purchased Barnett Shale properties for $40.5 million, which are subject to certain post-closing adjustments. In first quarter 2008, we purchased Barnett Shale properties for $281.5 million and an add-on to this acquisition in second quarter 2008 for $10.7 million. After recording asset retirement obligations and transaction costs of $646,000, the purchase price allocated to proved properties was $219.7 million and unproved properties was $73.2 million.

Dispositions

     In first quarter 2008, we sold shallow oil properties located in East Texas for proceeds of $64.4 million and recorded a gain of $20.1 million. In first quarter 2007, we sold Austin Chalk properties for proceeds of $80.4 million and recorded a loss on the sale of $2.3 million. In first quarter 2007, we also sold Gulf of Mexico properties for proceeds of $155.0 million and recorded a gain on the sale of $95.1 million. We have reflected the results of operations of the Austin Chalk and Gulf of Mexico divestitures as discontinued operations rather than a component of continuing operations for 2007. See Note 5 for additional information.

(5) DISCONTINUED OPERATIONS

     As part of our Stroud acquisition in 2006, we purchased Austin Chalk properties in Central Texas, which we sold in first quarter 2007 for proceeds of $80.4 million. In first quarter 2007, we also sold our Gulf of Mexico properties for proceeds of $155.0 million. Discontinued operations for the three months and the six months ended June 30, 2007 are summarized as follows (in thousands):

		Three Months				Six Months
		Ended				Ended
		June 30,				June 30,
		2007				2007
Revenues:
Oil and gas sales		$	(1,096	)		$	15,187
Transportation and gathering			(58	)			10
Other			—				310
(Loss) gain on disposition of assets and other			(406	)			93,055
			(1,560	)			108,562
Costs and expenses:
Direct operating			(198	)			2,559
Production and ad valorem taxes			—				141
Exploration and other			146				212
Interest expense			—				845
Depletion, depreciation and amortization			—				6,672
			(52	)			10,429
(Loss) income from discontinued operations before income taxes			(1,508	)			98,133
Income tax (benefit) expense			(529	)			34,344
(Loss) income from discontinued operations, net of taxes		$	(979	)		$	63,789
Production:
Crude oil (bbls)			—				40,634
Natural gas (mcf)			—				1,990,277
Total (mcfe)			—				2,234,081

(6) INCOME TAXES

     Income tax included in continuing operations was as follows (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Income tax (benefit) expense		$	(20,869	)		$	34,348			$	(13,393	)		$	39,179
Effective tax rate			37.6	%			34.5	%			29.0	%			34.8	%

     We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended June 30, 2008 and 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. For the six months ended June 30, 2008, our overall effective tax rate for continuing operations was different than the statutory rate of 35% due to state income taxes, a decrease in our deferred tax asset related to state tax credit carryforwards for additional tax expense of $1.5 million and a valuation allowance against a deferred tax asset related to our deferred compensation plan for additional tax expense of $2.5 million. For the six months ended June 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. We expect our effective tax rate to be approximately 38% for the remainder of 2008.

     At December 31, 2007, we had regular tax net operating loss (“NOL”) carryforwards of $204.4 million and alternative minimum tax (“AMT”) NOL carryforwards of $149.7 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2007 was $39.7 million, net of the SFAS No. 123(R) deduction for unrealized benefits. We have $26.9 million of NOLs generated in years before 1998, which are subject to yearly limitations due to IRC Section 382. We do not believe the application of the Section 382 limitations hinders our ability to use such NOLs and therefore, no valuation allowance has been provided. At December 31, 2007, we had AMT credit carryforwards of $777,000 that are not subject to limitation or expiration. We expect to make AMT estimated tax payments of $1.0 million in 2008 and utilize approximately $38.0 million in regular NOL carryforwards and $45.0 million of AMT NOL carryforwards during 2008.

(7) EARNINGS PER COMMON SHARE

     The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Numerator:
(Loss) income from continuing operations		$	(34,582	)		$	65,185			$	(32,842	)		$	73,554
(Loss) income from discontinued operations, net of taxes			—				(979	)			—				63,789
Net (loss) income		$	(34,582	)		$	64,206			$	(32,842	)		$	137,343
Denominator:
Weighted average shares outstanding			153,203				146,214				151,565				142,733
Stock held in the deferred compensation plan and treasury shares			(2,431	)			(1,045	)			(2,350	)			(1,089	)
Weighted average shares, basic			150,772				145,169				149,215				141,644
Effect of dilutive securities:
Weighted average shares outstanding			150,772				146,214				149,215				142,733
Employee stock options, SARs and stock held in the deferred compensation plan			—				3,968				—				3,883
Dilutive potential common shares for diluted earnings per share			150,772				150,182				149,215				146,616
Earnings per common share basic and diluted:
Basic — (loss) income from continuing operations		$	(0.23	)		$	0.45			$	(0.22	)		$	0.52
— discontinued operations			—				(0.01	)			—				0.45
— net (loss) income			(0.23	)			0.44				(0.22	)			0.97
Diluted — (loss) income from continuing operations		$	(0.23	)		$	0.43			$	(0.22	)		$	0.50
— discontinued operations			—				—				—				0.44
— net (loss) income			(0.23	)			0.43				(0.22	)			0.94

     Due to our net loss from continuing operations for the three months and the six months ended June 30, 2008, we excluded all 10.0 million of outstanding stock options/SARs and restricted stock because the effect would have been anti-dilutive. Stock appreciation rights, or SARs, for 271,000 and 140,000 shares were outstanding but not included in the computations of diluted net income per share for the three months and the six months ended June 30, 2007 because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations.

(8) SUSPENDED EXPLORATORY WELL COSTS

     The following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, 2008 and the year ended December 31, 2007 (in thousands):

		June 30,				December 31,
		2008				2007
Beginning balance at January 1		$	15,053			$	9,984
Additions to capitalized exploratory well costs pending the determination of proved reserves			36,542				14,428
Reclassifications to wells, facilities and equipment based on determination of proved reserves			(6,235	)			—
Capitalized exploratory well costs charged to expense			(3,598	)			(8,034	)
Divested wells			—				(1,325	)
Balance at end of period			41,762				15,053
Less exploratory well costs that have been capitalized for a period of one year or less			(38,014	)			(12,067	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$	3,748			$	2,986
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			2				2

     The $41.8 million of capitalized exploratory well costs at June 30, 2008 was incurred in 2008 ($31.8 million), in 2007 ($7.0 million) and in 2006 ($3.0 million).

(9) INDEBTEDNESS

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at June 30, 2008 is shown parenthetically). No interest expense was capitalized during the three or the six months ended June 30, 2008 and 2007.

		June 30,				December 31,
		2008				2007
Bank debt (4.9%)		$	206,000			$	303,500
Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount			197,781				197,602
6.375% Senior Subordinated Notes due 2015			150,000				150,000
7.5% Senior Subordinated Notes due 2016, net of discount			249,575				249,556
7.5% Senior Subordinated Notes due 2017			250,000				250,000
7.25% Senior Subordinated Notes due 2018			250,000				—
Total debt		$	1,303,356			$	1,150,658

Bank Debt

     In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the $1.0 billion facility amount or the borrowing base. On June 30, 2008, the borrowing base was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. Subject to certain conditions, the facility amount may be increased to the borrowing base amount with twenty days notice. At June 30, 2008, the outstanding balance under the bank credit facility was $206.0 million and there was $794.0 million of borrowing capacity available. The loan matures October 25, 2012. Borrowing under the bank credit facility can either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to the lesser of (i) the maximum rate (the “weekly ceiling” as defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the “Maximum Rate”) or, (ii) the sum of the higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for such data plus one-half of one percent (0.50%) per annum, plus a base rate margin of between 0.0% to 0.5% per annum depending on the total outstanding under the bank credit facility relative to the borrowing base. On all LIBOR loans, we pay a varying rate per annum equal to

the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.0% and 1.75% per annum depending on the total outstanding under the bank credit facility relative to the borrowing base. We may elect, from time-to-time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any part of the base rate loans to LIBOR loans. The weighted average interest rate on the bank credit facility was 4.8% for the three months ended June 30, 2008 compared to 6.5% for the three months ended June 30, 2007. The weighted average interest rate on the bank credit facility for the six months ended June 30, 2008 was 4.9% compared to 6.5% in the same period of the prior year. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At June 30, 2008, the commitment fee was 0.25% and the interest rate margin was 1.0%. At July 21, 2008, the interest rate (including applicable margin) was 4.9%.

Senior Subordinated Notes

     In May 2008, we issued $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 (“7.25% Notes”). Interest on the 7.25% Notes is payable semi-annually, in May and November, and is guaranteed by certain of our subsidiaries. We may redeem the 7.25% Notes, in whole or in part, at any time on or after May 1, 2013, at redemption prices of 103.625% of the principal amount as of May 1, 2013 and declining to 100.0% on May 1, 2016 and thereafter. Before May 1, 2011, we may redeem up to 35% of the original aggregate principal amount of the 7.25% Notes at a redemption price equal to 107.25% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that at least 65% of the original aggregate principal amount of the 7.25% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering.

Debt Covenants

     Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge or consolidate or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of greater than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at June 30, 2008.

     The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At June 30, 2008, we were in compliance with these covenants.

(10) ASSET RETIREMENT OBLIGATIONS

     Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. A reconciliation of our liability for plugging, abandonment and remediation costs for the six months ended June 30, 2008 is as follows (in thousands):

		Six Months Ended
		June 30,
		2008
Beginning of period		$	75,308
Liabilities incurred			1,781
Liabilities settled			(657	)
Disposition of wells			(898	)
Accretion expense			2,863
Change in estimate			1,689
End of period		$	80,086

     Accretion expense is recognized as a component of depreciation, depletion and amortization.

(11) CAPITAL STOCK

     In May 2008, at our annual meeting, our shareholders approved an increase to our number of authorized shares of common stock. We now have authorized capital stock of 485 million shares, which includes 475 million shares of common stock and 10 million shares of preferred stock. The following is a summary of changes in the number of common shares outstanding since the beginning of 2007:

		Six				Year
		Months Ended				Ended
		June 30,				December 31,
		2008				2007
Beginning balance			149,667,497				138,931,565
Public offering			4,435,300				8,050,000
Stock options/SARs exercised			821,707				2,220,627
Restricted stock grants			158,066				408,067
In lieu of bonuses			8,988				29,483
Contributed to 401(k) plan			—				27,755
			5,424,061				10,735,932
Ending balance			155,091,558				149,667,497

     In May 2008, we completed a public offering of 4.4 million shares of common stock at $66.38 per share. After underwriting discount and other offering costs of $12.5 million, net proceeds of $281.9 million were used to repay indebtedness on our bank credit facility.

Treasury Stock

     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities.

(12) DERIVATIVE ACTIVITIES

     At June 30, 2008, we had open swap contracts covering 54.1 Bcf of gas at prices averaging $8.57 per mcf. We also had collars covering 67.6 Bcf of gas at weighted average floor and cap prices of $8.17 to $9.47 per mcf and 4.6 million barrels of oil at weighted average floor and cap prices of $62.32 to $75.81 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract prices and a reference price, generally New York Mercantile Exchange (“NYMEX”), on June 30, 2008, was a net unrealized pre-tax loss of $745.3 million. These contracts expire monthly through December 2009.

     The following table sets forth our derivative volumes by year as of June 30, 2008:

						Average
Period		Contract Type		Volume Hedged		Hedge Price
Natural Gas
2008		Swaps		155,000 Mmbtu/day		$8.73
2008		Collars		70,000 Mmbtu/day		$7.73 — $10.36
2009		Swaps		70,000 Mmbtu/day		$8.38
2009		Collars		150,000 Mmbtu/day		$8.28 — $9.27
Crude Oil
2008		Collars		9,000 bbl/day		$59.34 — $75.48
2009		Collars		8,000 bbl/day		$64.01 — $76.00

     Under SFAS No. 133, every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying estimated market price at the determination date. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive loss, which is later transferred to earnings when the hedged transaction occurs. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized in earnings. As of June 30, 2008, an unrealized pre-tax derivative loss of $450.5 million was recorded in the balance sheet caption accumulated other comprehensive income (loss). This loss is expected to be reclassified into earnings in 2008 ($162.9 million) and 2009 ($287.6 million). The actual reclassification to earnings will be based on market prices at the contract settlement date.

     For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly and are included as increases or decreases to oil and gas sales in the period the hedged production is sold. Oil and gas sales include $50.0 million and $44.8 million of losses in the three months and the six months ended June 30, 2008 compared to a loss of $1.8 million and a gain of $10.0 million in the three months and the six months ended June 30, 2007. Any ineffectiveness associated with these hedges is reflected in the income statement caption derivative fair value loss. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged. The six months ended June 30, 2008 includes ineffective unrealized losses of $2.7 million compared to gains of $530,000 in the same period of 2007.

     Some of our derivatives do not qualify for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in the income statement caption called derivative fair value loss (see table below). As a result of the sale of our Gulf of Mexico assets in first quarter 2007, a portion of our derivatives, which was designated to our Gulf Coast production, is marked to market. In fourth quarter 2007, we began marking a portion of our oil hedges to market due to the anticipated sale of a portion of our East Texas properties, which was sold in first quarter 2008.

     During third and fourth quarter 2007, in addition to the swaps and collars discussed above, we entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix a portion of our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $11.7 million at June 30, 2008 and expire through 2010.

Derivative Fair Value (Loss) Income

     The following table presents information about the components of derivative fair value loss in the three months and the six months ended June 30, 2008 and 2007 (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Hedge ineffectiveness — realized		$	(490	)		$	—			$	215			$	—
— unrealized			558				749				(2,691	)			530
Change in fair value of derivatives that do not qualify for hedge accounting			(164,006	)			20,322				(299,227	)			(45,789	)
Realized (loss) gain on settlements — gas (a)			(28,256	)			7,695				(11,672	)			31,405
Realized loss on settlements — oil (a)			(6,216	)			—				(8,802	)			—
Derivative fair value (loss) income		$	(198,410	)		$	28,766			$	(322,177	)		$	(13,854	)

     The combined fair value of derivatives included in our consolidated balance sheets as of June 30, 2008 and December 31, 2007 is summarized below (in thousands). Derivative activities are conducted with major financial and commodities trading institutions, which we believe are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. We have master netting agreements with our counterparties and the credit worthiness of our counterparties is subject to periodic review.

		June 30,				December 31,
		2008				2007
Derivative assets:
Natural gas — swaps		$	—			$	54,577
— collars			—				4,916
— basis swaps			4,821				1,082
Crude oil — collars			—				(6,475	)
		$	4,821			$	54,100
Derivative liabilities:
Natural gas — swaps		$	(236,417	)		$	6,594
— collars			(218,277	)			11,302
— basis swaps			6,874				(937	)
Crude oil — collars			(290,645	)			(93,235	)
		$	(738,465	)		$	(76,276	)

Fair Value Measurements

     Effective January 1, 2008, we adopted SFAS No. 157, as discussed in Note 3, which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which include multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset.

     SFAS No. 157 does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among techniques. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and lowest priority to unobservable inputs (level 3 measurements). The three levels of fair value hierarchy defined by SFAS No. 157 are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data, which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2008, we have no significant Level 3 measurements.

     We use a market approach for our fair value measurements. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis, as set forth in SFAS No. 157 (in thousands):

						Fair Value Measurements at June 30, 2008 Using
						Quoted Prices in				Significant Other				Significant
		Total Carrying				Active Markets for				Observable				Unobservable
		Value as of				Identical Assets				Inputs				Inputs
		June 30, 2008				(Level 1)				(Level 2)				(Level 3)
Trading securities held in the deferred compensation plans		$	48,640			$	48,640			$	—			$	—
Derivatives — swaps			(236,417	)			—				(236,417	)			—
— collars			(508,922	)			—				(508,922	)			—
— basis swaps			11,695				—				11,695				—

     These items are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Our trading securities in Level 1 are exchange — traded and measured at fair value with a market approach using June 30, 2008 market values. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services to corroborate market data.

(13) EMPLOYEE BENEFIT AND EQUITY PLANS

     We have six equity-based stock plans, of which two are active. Under the active plans, incentive and non-qualified options, SARs and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of outside, independent directors from the Board of Directors. All awards granted have been issued at prevailing market prices at the time of the grant. Information with respect to stock option and SARs activities is summarized below:

						Weighted
						Average
						Exercise
		Shares				Price
Outstanding on December 31, 2007			7,772,325			$	17.95
Granted			1,134,180				63.77
Exercised			(1,063,015	)			15.01
Expired/forfeited			(38,098	)			38.85
Outstanding on June 30, 2008			7,805,392			$	24.90

     The following table shows information with respect to outstanding stock options and SARs at June 30, 2008:

		Outstanding												Exercisable
						Weighted-Average				Weighted-Average								Weighted-Average
						Remaining				Exercise								Exercise
Range of Exercise Prices		Shares				Contractual Life				Price				Shares				Price
$ 1.29  — $  9.99			1,982,863			2.09				$	4.75				1,982,863			$	4.75
10.00 —   19.99			1,906,310			1.83					16.25				1,906,310				16.25
20.00 —   29.99			1,313,046			2.75					24.36				699,616				24.24
30.00 —   39.99			1,466,498			3.74					33.97				404,507				34.59
40.00 —   49.99			17,540			4.31					42.59				360				41.01
50.00 —   59.99			743,970			4.62					58.57				180				58.60
60.00 —   69.99			28,427			4.88					65.33				—				—
70.00 —   75.00			346,738			4.89					75.00				26,484				75.00
Total			7,805,392			2.83				$	24.90				5,020,320			$	14.61

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2008 was $20.66. The fair value of each stock option/SAR granted during 2008 was estimated as of the date of grant using the Black-Scholes-Merton option-pricing model based on the following average assumptions: risk-free interest rate of 2.41%; dividend yield of 0.25%; expected volatility of 41%; and an expected life of 3.5 years.

     As of June 30, 2008, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $320.5 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $255.9 million and 2.23 years. As of June 30, 2008, the number of fully vested awards and awards expected to vest was 7.6 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $24.33 and 2.8 years and the aggregate intrinsic value was $317.0 million. As of June 30, 2008, unrecognized compensation cost related to the awards was $31.0 million, which is expected to be recognized over a weighted average period of 1.4 years.

Restricted Stock Grants

     During the first six months of 2008, 312,500 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $65.84 with a three-year vesting period and 10,800 shares were granted to our directors at a price of $75.00 with immediate vesting. In the first six months of 2007, we issued 407,400 shares of restricted stock as compensation to employees at an average price of $34.59 with a three year vesting period and 15,900 shares were granted to our directors at a price of $38.02 with immediate vesting. We recorded compensation expense related to restricted stock grants which is based upon the market value of the shares on the date of grant of $7.4 million in the first six months of 2008 compared to $4.2 million in the six-month period ended June 30, 2007. As of June 30, 2008, unrecognized compensation cost related to restricted stock awards was $31.0 million, which is expected to be recognized over the next 3 years. All of our restricted stock grants are held in our deferred compensation plans (see discussion below). The vesting of these shares is dependent only upon the employees’ continued service with us.

     A summary of the status of our non-vested restricted stock outstanding at June 30, 2008 is presented below:

						Weighted
						Average Grant
		Shares				Date Fair Value
Non-vested shares outstanding at December 31, 2007			563,660			$	30.42
Granted			323,289				65.84
Vested			(208,101	)			37.73
Forfeited			(6,113	)			40.49
Non-vested shares outstanding at June 30, 2008			672,735			$	45.57

Deferred Compensation Plan

     In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan (“2005 Deferred Compensation Plan”). The 2005 Deferred Compensation Plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest such amounts in Range common stock or make other investments at the individual’s discretion. The assets of the plan are held in a rabbi trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock granted and held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The vested portion of the stock held in the Rabbi Trust is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than Range common stock, are invested in marketable securities and reported at market value in other assets on our consolidated balance sheet. Changes in the market value of the securities are charged or credited to deferred compensation plan expense each quarter. The deferred compensation liability on our balance sheet reflects the vested market value of the marketable securities and stock held in the Rabbi Trust. We recorded non-cash, mark-to-market expense related to our deferred compensation plan of $7.5 million and $28.1 million in the second quarter and the first six months of 2008 compared to $9.3 million and $20.6 million in the same periods of 2007.

(14) SUPPLEMENTAL CASH FLOW INFORMATION

		Six Months Ended
		June 30,
		2008				2007
		(in thousands)
Non-cash investing and financing activities included:
Asset retirement costs capitalized		$	3,175			$	2,145
Net cash provided from operating activities included:
Income taxes paid		$	2,320			$	44
Interest paid			43,189				35,776

     The consolidated statement of cash flows for the six months ended June 30, 2008 excludes the following non-cash transactions: grants of 323,000 restricted shares, vesting of 208,000 restricted shares and forfeitures of 6,000 restricted shares.

(15) COMMITMENTS AND CONTINGENCIES

Litigation

     We are involved in various legal actions and claims arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

(16) CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION ^(a)

		June 30,				December 31,
		2008				2007
		(in thousands)
Oil and gas properties:
Properties subject to depletion		$	4,783,732			$	4,172,151
Unproved properties			421,815				271,426
Total			5,205,547				4,443,577
Accumulated depreciation, depletion and amortization			(1,043,099	)			(939,769	)
Net capitalized costs		$	4,162,448			$	3,503,808

(17) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT ^(a)

		Six Months
		Ended				Year Ended
		June 30,				December 31,
		2008				2007
		(in thousands)
Acquisitions:
Unproved leasehold		$	103,660			$	4,552
Proved oil and gas properties			230,036				253,064
Asset retirement obligations			251				3,301
Acreage purchases			67,577				78,095
Development			378,835				734,987
Exploration:
Drilling			53,945				40,567
Expense			34,193				39,872
Stock-based compensation expense			1,862				3,473
Gas gathering facilities			18,339				18,655
Subtotal			888,698				1,176,566
Asset retirement obligations			3,175				(7,075	)
Total costs incurred		$	891,873			$	1,169,491

(18) ACCOUNTING STANDARDS NOT YET ADOPTED

     In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.” SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. For Range, SFAS No. 161 is effective January 1, 2009. We are in the process of evaluating the impact of SFAS No. 161 on our consolidated financial statements.

     In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The statement will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009. We are currently evaluating provisions of this statement.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2007 Annual Report on Form 10-K, as well as the consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For additional risk factors affecting our business, see the information in Item 1A. Risk Factors, in our 2007 Annual Report on Form 10-K and subsequent filings. Except where noted, discussions in this report relate only to our continuing operations.

Critical Accounting Estimates and Policies

     The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. There have been no significant changes to our critical accounting estimates or policies subsequent to December 31, 2007.

Results of Continuing Operations

Overview

     Total revenues decreased 38% for second quarter 2008 over the same period of 2007. The decrease includes a 63% increase in oil and gas sales more than offset by a $227.2 million increase in derivative fair value loss. Oil and gas sales vary due to changes in volumes of production sold and realized commodity prices. For second quarter 2008, production increased 22% from the same period of the prior year with the continued success of our drilling program and our acquisitions. Realized prices were higher by 16% in second quarter 2008 when compared to second quarter of 2007. We believe prices will continue to remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy and the level of oil and gas production in North America and worldwide.

     All of our expenses increased on both an absolute and per mcfe basis during second quarter 2008 due to higher overall industry costs, higher compensation expense resulting from additional employees, increased salaries and higher levels of activity. While overall costs were higher, the rate of inflation experienced in our industry during 2007 appears to have moderated for some goods and services, but is increasing for other goods such as steel. The availability of goods and services continues to be mixed. As we continue to have Marcellus wells shut-in waiting on pipeline and processing facilities, we expect to see continued upward pressure on our cost structure. The initial phase of the pipeline and processing infrastructure is expected to be completed in first quarter 2009.

Oil and Gas Sales, Production and Realized Price Calculation

     Our oil and gas sales vary from quarter to quarter as a result of changes in realized commodity prices or volumes of production sold. Hedges included in oil and gas sales reflect settlement on those derivatives that qualify for hedge accounting. Cash settlement of derivative contracts that are not accounted for as hedges are included in the income statement caption called derivative fair value loss. The following table summarized the primary components of oil and gas sales for the three months and the six months ended June 30, 2008 and 2007 (in thousands):

		Three Months Ended																Six Months Ended
		June 30,																June 30,
		2008				2007				Change				%				2008				2007				Change				%
Oil wellhead		$	99,715			$	54,840			$	44,875				82	%		$	171,134			$	101,801			$	69,333				68	%
Oil hedges realized			(33,033	)			(1,936	)			(31,097	)			1,606	%			(48,425	)			(1,948	)			(46,477	)			2,386	%
Total oil revenue			66,682				52,904				13,778					26	%		122,709				99,853				22,856				23	%
Gas wellhead			279,054				149,602				129,452				87	%			493,570				275,926				217,644				79	%
Gas hedges realized			(16,926	)			87				(17,013	)			19,555	%			3,648				11,901				(8,253	)			69	%
Total gas revenue			262,128				149,689				112,439				75	%			497,218				287,827				209,391				73	%
NGL			18,812				11,303				7,509				66	%			35,079				19,532				15,547				80	%
Combined wellhead			397,581				215,745				181,836				84	%			699,783				397,259				302,524				76	%
Combined hedges			(49,959	)			(1,849	)			(48,110	)			2,602	%			(44,777	)			9,953				(54,730	)			550	%
Total oil and gas sales		$	347,622			$	213,896			$	133,726				63	%		$	655,006			$	407,212			$	247,794				61	%

     Our production continues to grow through continued drilling success and additions from acquisitions. For second quarter 2008, our production volumes increased, from the same period of the prior year, 22% in our Appalachian Area, 20% in our Southwestern Area and 75% in our Gulf Coast Area. For the six months ended June 30, 2008, our production volumes increased, when compared to the prior year, 24% in our Appalachian Area, 23% in our Southwestern Area and 65% in our Gulf Coast Area. Our production for the three months and the six months ended June 30, 2008 and 2007 is shown below:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Production:
Crude oil (bbls)			829,144				881,641				1,583,689				1,720,129
NGLs (bbls)			335,231				280,407				647,731				553,537
Natural gas (mcf)			27,653,005				21,514,007				54,975,779				41,208,030
Total (mcfe) (a)			34,639,255				28,486,295				68,364,299				54,850,026
Average daily production:
Crude oil (bbls)			9,111				9,688				8,702				9,503
NGLs (bbls)			3,684				3,081				3,559				3,058
Natural gas (mcf)			303,879				236,418				302,065				227,669
Total (mcfe) (a)			380,651				313,036				375,628				303,039

     Our average realized price (including all derivative settlements) received for oil and gas was $9.03 per mcfe in second quarter 2008 compared to $7.78 per mcfe in the same period of the prior year. Our average realized price calculation (including all derivative settlements) includes all cash settlement for derivatives, whether or not they qualify for hedge accounting. Average price calculations for the three months and the six months ended June 30, 2008 and 2007 are shown below:

		Three Months Ended								Six Months Ended,
		June 30,								June 30,
		2008				2007				2008				2007
Average sales prices (wellhead):
Crude oil (per bbl)		$	120.26			$	62.20			$	108.06			$	59.18
NGLs (per bbl)		$	56.12			$	40.31			$	54.16			$	35.29
Natural gas (per mcf)		$	10.09			$	6.95			$	8.98			$	6.70
Total (per mcfe) (a)		$	11.48			$	7.57			$	10.24			$	7.25
Average realized price (including derivatives that qualify for hedge accounting):
Crude oil (per bbl)		$	80.42			$	60.01			$	77.48			$	58.05
NGLs (per bbl)		$	56.12			$	40.31			$	54.16			$	35.29
Natural gas (per mcf)		$	9.48			$	6.96			$	9.04			$	6.98
Total (per mcfe) (a)		$	10.04			$	7.51			$	9.58			$	7.42
Average realized price (including all derivative settlements):
Crude oil (per bbl)		$	72.34			$	60.01			$	71.34			$	58.05
NGLs (per bbl)		$	56.12			$	40.31			$	54.16			$	35.29
Natural gas (per mcf)		$	8.46			$	7.32			$	8.85			$	7.75
Total (per mcfe) (a)		$	9.03			$	7.78			$	9.28			$	8.00
Average NYMEX prices (b)
Oil (per bbl)		$	123.98			$	65.03			$	111.66			$	61.65
Natural gas (per mcf)		$	10.80			$	7.56			$	9.45			$	7.26